Reducing Effects of Rig Noise on Telemetry

ABSTRACT

Apparatus and methods for reducing effects of rig noise on telemetry. A method may include commencing operation of a telemetry system of a drilling rig and commencing operation of an equipment controller of the drilling rig. Commencing operation of the equipment controller may cause the equipment controller to automatically output control commands to automatically change operational parameters of the telemetry system and/or rig equipment of the drilling rig to reduce interference by rig noise with a telemetry signal.

BACKGROUND OF THE DISCLOSURE

Wells are generally drilled into the ground or ocean bed to recover natural deposits of oil, gas, and other materials that are trapped in subterranean rock formations. Well construction (e.g., drilling) operations may be performed at a wellsite by a well construction system (e.g., a drilling rig) having various surface and subterranean well construction equipment (e.g., rig equipment) operating in a coordinated manner. For example, a drive mechanism, such as a top drive located at a wellsite surface, can be utilized to rotate and advance a drill string into a subterranean rock formation to drill a wellbore. The drill string may include a plurality of drill pipes coupled together and terminating with a drill bit. Length of the drill string may be increased by adding additional drill pipes while depth of the wellbore increases. Drilling fluid may be pumped from the wellsite surface down through the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit, and carries drill cuttings from the wellbore back to the wellsite surface. The drilling fluid returning to the surface may then be cleaned and again pumped through the drill string. The equipment of the well construction system may be grouped into various subsystems, wherein each subsystem performs a different operation.

During well drilling operations, downhole telemetry (e.g., mud-pulse telemetry, electromagnetic telemetry) may be utilized to communicate information between a bottom-hole assembly (BHA) of a drill string and surface equipment. Mud-pulse telemetry transmits downhole (e.g., sensor) data between the surface equipment and the BHA in the form of modulated pressure pulses generated by a downhole transmitter. The pressure pulses propagate to a surface receiver (i.e., a pressure sensor) through a drilling fluid transferred downhole through the drill string. Conversely, electromagnetic telemetry transmits downhole data between the surface equipment and the BHA in the form of modulated electromagnetic waves generated by a downhole transmitter. The electromagnetic waves propagate to a surface receiver (i.e., an electromagnetic probe) through the rock formation extending between the downhole transmitter and the surface receiver.

Efficiency of mud-pulse telemetry and electromagnetic telemetry is affected by noise generated by the well construction equipment (i.e., rig noise), which can interfere with telemetry signals communicated between the downhole transmitters and surface receivers. When rig noise interferes with telemetry signals, sensor data encoded in such telemetry signals cannot be correctly extracted (e.g., demodulated) and the telemetry operations have to be repeated, thereby resulting in flat time for rig operations.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

The present disclosure introduces an apparatus including a telemetry system of a drilling rig and an equipment controller comprising a processor and a memory storing computer program code. The telemetry system includes a transmitter and a receiver. The transmitter is carried by a drill string and is operable to transmit a telemetry signal. The receiver is included in surface equipment of the drilling rig. The receiver is operable to generate an output signal including a telemetry signal signature, based on the telemetry signal, and a rig noise signature, based on rig noise generated by rig equipment of the drilling rig. The equipment controller is operable to automatically reduce interference by the rig noise with the telemetry signal by outputting control commands to change operational parameters of the rig equipment and/or the telemetry system.

The present disclosure also introduces a method including commencing operation of a telemetry system of a drilling rig and commencing operation of an equipment controller of the drilling rig, thereby causing the equipment controller to output control commands to change operational parameters of the telemetry system and/or rig equipment of the drilling rig to reduce interference by rig noise with a telemetry signal.

The present disclosure also introduces a method including commencing operation of a telemetry system a drilling rig and manually operating a control workstation of the drilling rig by a rig personnel to change operational parameters of the rig equipment and/or the telemetry system to reduce interference by rig noise with a telemetry signal.

These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 4 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 5 is a graph according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.

FIG. 1 is a schematic view of at least a portion of an example implementation of a well construction system 100 according to one or more aspects of the present disclosure. The well construction system 100 represents an example environment in which one or more aspects of the present disclosure described below may be implemented. The well construction system 100 may be or comprise a drilling rig and associated equipment. Although the well construction system 100 is depicted as an onshore implementation, the aspects described below are also applicable to offshore implementations.

The well construction system 100 is depicted in relation to a wellbore 102 formed by rotary and/or directional drilling from a wellsite surface 104 and extending into a subterranean rock formation 106. The well construction system 100 comprises well construction equipment, such as surface equipment 110 located at the wellsite surface 104 and a drill string 120 suspended within the wellbore 102. The surface equipment 110 may include a mast, a derrick, and/or another support structure 112 disposed over a rig floor 114. The drill string 120 may be suspended within the wellbore 102 from the support structure 112. The support structure 112 and the rig floor 114 are collectively supported over the wellbore 102 by legs and/or other support structures (not shown). Certain pieces of surface equipment 110 may be manually operated (e.g., by hand, via a local control panel) by rig personnel 195 (e.g., a roughneck or another human rig operator) located at various portions (e.g., rig floor 114) of the well construction system 100.

The drill string 120 may comprise a bottom-hole assembly (BHA) 124 and means 122 for conveying the BHA 124 within the wellbore 102. The conveyance means 122 may comprise drill pipe, heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough logging condition (TLC) pipe, and/or other means for conveying the BHA 124 within the wellbore 102. A downhole end of the BHA 124 may include or be coupled to a drill bit 126. Rotation of the drill bit 126 and the weight of the drill string 120 collectively operate to form the wellbore 102. The drill bit 126 may be rotated by a driver at the wellsite surface 104 and/or via a downhole mud motor 182 connected with the drill bit 126. The BHA 124 may also include one or more downhole tools 180 above and/or below the mud motor 182.

The downhole tools 180 may be or comprise a measurement-while-drilling (MWD) or logging-while-drilling (LWD) tool comprising downhole sensors 184 operable for the acquisition of measurement data pertaining to the BHA 124, the wellbore 102, and/or the rock formation 106. The downhole sensors 184 may comprise an inclination sensor, a rotational position sensor, and/or a rotational speed sensor, which may include one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and/or other sensors for determining the orientation, position, and/or speed of one or more portions of the BHA 124 (e.g., the drill bit 126, the downhole tool 180, the mud motor 182) and/or other portions of the tool string 120 relative to the wellbore 102 and/or the wellsite surface 104. The downhole sensors 184 may comprise a depth correlation tool utilized to determine and/or log position (i.e., depth) of one or more portions of the BHA 124 and/or other portions of the tool string 120 within the wellbore 102 and/or with respect to the wellsite surface 104.

One or more of the downhole tools 180 and/or another portion of the BHA 124 may also comprise a telemetry device 186 operable to communicate with the surface equipment 110 via downhole telemetry, such as mud-pulse telemetry and/or electromagnetic telemetry. One or more of the downhole tools 180 and/or another portion of the BHA 124 may also comprise a downhole controller 188 operable to receive, process, and/or store data received from the surface equipment 110, the downhole sensors 184, and/or other portions of the BHA 124. The controller 188 may also store executable computer programs (e.g., program code instructions), including for implementing one or more aspects of the operations described herein.

The support structure 112 may support the driver, such as a top drive 116, operable to connect (perhaps indirectly) with an upper end of the drill string 120, and to impart rotary motion 117 and vertical motion 135 to the drill string 120, including the drill bit 126. However, another driver, such as a kelly and a rotary table (neither own), may be utilized in addition to or instead of the top drive 116 to impart the rotary motion 117 to the drill string 120. The top drive 116 and the connected drill string 120 may be suspended from the support structure 112 via a hoisting system or equipment, which may include a traveling block 113, a crown block 115, and a drawworks 118 storing a support cable or line 123. The crown block 115 may be connected to or otherwise supported by the support structure 112, and the traveling block 113 may be coupled with the top drive 116. The drawworks 118 may be mounted on or otherwise supported by the rig floor 114. The crown block 115 and traveling block 113 comprise pulleys or sheaves around which the support line 123 is reeved to operatively connect the crown block 115, the traveling block 113, and the drawworks 118 (and perhaps an anchor). The drawworks 118 may, thus, selectively impart tension to the support line 123 to lift and lower the top drive 116, resulting in the vertical motion 135. The drawworks 118 may comprise a drum, a base, and a prime mover (e.g., an engine or motor) (not shown) operable to drive the drum to rotate and reel in the support line 123, causing the traveling block 113 and the top drive 116 to move upward. The drawworks 118 may be further operable to reel out the support line 123 via a controlled rotation of the drum, causing the traveling block 113 and the top drive 116 to move downward.

The top drive 116 may comprise a grabber, a swivel (neither shown), elevator links 127 terminating with an elevator 129, and a drive shaft 125 operatively connected with a prime mover (e.g., an electric motor) (not shown) of the top drive 116, such as via a gear box or transmission (not shown). The drive shaft 125 may be selectively coupled with the upper end of the drill string 120 and the prime mover may be selectively operated to rotate the drive shaft 125 and the drill string 120 coupled with the drive shaft 125. Hence, during drilling operations, the top drive 116, in conjunction with operation of the drawworks 118, may advance the drill string 120 into the formation 106 to form the wellbore 102. The elevator links 127 and the elevator 129 of the top drive 116 may handle tubulars (e.g., drill pipes, drill collars, casing joints, etc.) that are not mechanically coupled to the drive shaft 125. For example, when the drill string 120 is being tripped into or out of the wellbore 102, the elevator 129 may grasp the tubulars of the drill string 120 such that the tubulars may be raised and/or lowered via the hoisting equipment mechanically coupled to the top drive 116. The top drive 116 may have a guide system (not shown), such as rollers that track up and down a guide rail on the support structure 112. The guide system may aid in keeping the top drive 116 aligned with the wellbore 102, and in preventing the top drive 116 from rotating during drilling by transferring reactive torque to the support structure 112.

The well construction system 100 may further include a drilling fluid circulation system or equipment operable to circulate fluids between the surface equipment 110 and the drill bit 126 during drilling and other operations. For example, the drilling fluid circulation system may be operable to inject a drilling fluid from the wellsite surface 104 into the wellbore 102 via an internal fluid passage 121 extending longitudinally through the drill string 120. The drilling fluid circulation system may comprise a pit, a tank, and/or other fluid container 142 holding the drilling fluid 140 (i.e., mud), and one or more drilling fluid pumps 144 (i.e., mud pumps) operable to move the drilling fluid 140 from the container 142 into the fluid passage 121 of the drill string 120 via a fluid conduit 145 (e.g., stand pipe) extending from the pumps 144 to the top drive 116 and an internal passage extending through the top drive 116.

During drilling operations, the drilling fluid may continue to flow downhole through the internal passage 121 of the drill string 120, as indicated by directional arrow 158. The drilling fluid may exit the BHA 124 via ports in the drill bit 126 and then circulate uphole through an annular space 108 of the wellbore 102 defined between an exterior of the drill string 120 and the sidewall of the wellbore 102, such flow being indicated by directional arrows 159. In this manner, the drilling fluid lubricates the drill bit 126 and carries formation cuttings uphole to the wellsite surface 104. The drilling fluid flowing downhole through the internal passage 121 may selectively actuate the mud motor 182 to rotate the drill bit 126 instead of or in addition to the rotation of the drill string 120 via the top drive 116. Accordingly, rotation of the drill bit 126 caused by the top drive 116 and/or mud motor 182 may advance the drill string 120 through the formation 106 to form the wellbore 102.

The well construction system 100 may further include fluid control equipment 130 for maintaining well pressure control and for controlling fluid being discharged from the wellbore 102. The fluid control equipment 130 may be mounted on top of a wellhead 134. The drilling fluid flowing uphole 159 toward the wellsite surface 104 may exit the annulus 108 via one or more instances of the fluid control equipment 130, such as a bell nipple, an RCD, and/or a ported adapter (e.g., a spool, cross adapter, a wing valve, etc.). The drilling fluid may then pass through drilling fluid reconditioning equipment 170 to be cleaned and reconditioned before returning to the fluid container 142. The drilling fluid reconditioning equipment 170 may also separate drill cuttings 146 from the drilling fluid into a cuttings container 148.

An iron roughneck 165 may be positioned on the rig floor 114. The iron roughneck 165 may comprise a torqueing portion 167, such as may include a spinner and a torque wrench comprising a lower tong and an upper tong. The torqueing portion 167 of the iron roughneck 165 may be moveable toward and at least partially around the drill string 120, such as may permit the iron roughneck 165 to make up and break out connections of the drill string 120. The torqueing portion 167 may also be moveable away from the drill string 120, such as may permit the iron roughneck 165 to move clear of the drill string 120 during drilling operations. The spinner of the iron roughneck 165 may be utilized to apply low torque to make up and break out threaded connections between tubulars of the drill string 120, and the torque wrench may be utilized to apply a higher torque to tighten and loosen the threaded connections.

A set of slips 162 may be located on the rig floor 114, such as may accommodate therethrough the drill string 120 during tubular make up and break out operations, tubular running operations, and drilling operations. The slips 162 may be in an open position during running and drilling operations to permit advancement of the drill string 120, and in a closed position to clamp the upper end (e.g., uppermost tubular) of the drill string 120 to thereby suspend and prevent advancement of the drill string 120 within the wellbore 102, such as during the make up and break out operations.

The surface equipment 110 of the well construction system 100 may also comprise a control center 190 from which various portions of the well construction system 100, such as a drill string rotation system (e.g., the top drive 116, the rotary table), a hoisting system (e.g., the drawworks 118, the blocks 113, 115), a tubular handling system (e.g., a catwalk, a tubular handling device), a drilling fluid circulation system (e.g., the pumps 144, the fluid conduit 145), a drilling fluid cleaning and reconditioning system (e.g., the drilling fluid reconditioning equipment 170, the containers 142, 148), the well control system (e.g., a BOP stack, a choke manifold), and the BHA 124, among other examples, may be monitored and controlled. The control center 190 may be located on the rig floor 114 or another location of the well construction system 100, such as the wellsite surface 104. The control center 190 may comprise a facility 191 (e.g., a room, a cabin, a trailer, etc.) containing a control workstation 197, which may be operated by rig personnel 195 (e.g., a driller or another human rig operator) to monitor and control various wellsite equipment or portions of the well construction system 100. The control workstation 197 may comprise or be communicatively connected with a surface equipment controller 192 (e.g., a processing device, a computer, etc.), such as may be operable to receive, process, and output information to monitor operations of and provide control to one or more portions of the well construction system 100. For example, the controller 192 may be communicatively connected with the various surface 110 and downhole 120 equipment described herein, and may be operable to receive signals (e.g., sensor data, sensor measurements) from and transmit signals (e.g., control data, control signals, control commands) to the equipment to perform various operations described herein. The controller 192 may store executable program code, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of methods and operations described herein. The controller 192 may be located within and/or outside of the facility 191.

The control workstation 197 may be operable for entering or otherwise communicating control commands to the controller 192 by the rig personnel 195, and for displaying or otherwise communicating information from the controller 192 to the rig personnel 195. The control workstation 197 may comprise a plurality of human-machine interface (HMI) devices, including one or more input devices 194 (e.g., a keyboard, a mouse, a joystick, a touchscreen, etc.) and one or more output devices 196 (e.g., a video monitor, a touchscreen, a printer, audio speakers, etc.). Communication between the controller 192, the input and output devices 194, 196, and the various wellsite equipment may be via wired and/or wireless communication means. However, for clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure.

Well construction systems within the scope of the present disclosure may include more or fewer components than as described above and depicted in FIG. 1. Additionally, various equipment and/or subsystems of the well construction system 100 shown in FIG. 1 may include more or fewer components than as described above and depicted in FIG. 1. For example, various engines, motors, hydraulics, actuators, valves, and/or other components not explicitly described herein may be included in the well construction system 100, and are within the scope of the present disclosure.

The present disclosure is further directed to various implementations of systems and/or methods for monitoring and/or controlling operations of telemetry equipment and/or well construction equipment (i.e., rig equipment) of a well construction system (i.e., a drilling rig) to reduce negative effects of (e.g., interference by) noise generated by the well construction equipment (referred to hereinafter as “rig noise”) on efficiency of telemetry. The systems and/or methods within the scope of the present disclosure may be utilized to monitor or otherwise determine (e.g., analyze, measure, evaluate) signatures of the rig noise and then to adjust or otherwise change operations of the telemetry equipment and/or well construction equipment based on the determined rig noise signatures to reduce interference to telemetry signal by the rig noise. For example, telemetry operations may be adjusted by performing the telemetry operations during a time interval when the rig noise is relatively low and/or at frequency ranges that are different from frequencies of the rig noise. The rig noise signatures may be displayed to rig personnel in conjunction with a signature of the telemetry signal. The rig personnel may then manually adjust or change the telemetry operations and/or well construction equipment operations based on the displayed rig noise signatures and telemetry signal signature to reduce the negative effects of rig noise on telemetry efficiency. The telemetry operations and/or well construction equipment operations may also or instead be adjusted or changed automatically by an equipment controller based on the rig noise signatures and telemetry signal signature to reduce the negative effects of rig noise on telemetry efficiency.

FIG. 2 is a schematic view of at least a portion of an example implementation of a telemetry system 200 for transmitting a telemetry signal 206 from a BHA 124 located downhole to surface equipment 110 according to one or more aspects of the present disclosure. The telemetry system 200 may operate in association with a fluid circulation system 202. The telemetry system 200 and the fluid circulation system 202 may form a portion of or operate in conjunction with the well construction system 100 shown in FIG. 1 and, thus, may comprise one or more features of the well construction system 100, including where indicated by the same reference numbers. Accordingly, the following description refers to FIGS. 1 and 2, collectively.

The telemetry system 200 may comprise a downhole mud-pulse telemetry device 204 (e.g., a mud-pulse transmitter) installed or otherwise disposed within the BHA 124 of a drill string 120 extending within a wellbore 102 and operable to communicate with the surface equipment 110 via mud-pulse telemetry. For example, the downhole telemetry device 204 may be operable to transmit the mud-pulse telemetry signal 206 (e.g., pressure pulses, pressure waves) uphole through drilling fluid being pumped downhole, to transmit downhole data to the surface equipment 110. The telemetry device 204 may be located within a downhole tool 180 of the BHA 124, which may further comprise a mud motor 182 and a drill bit 126. The downhole tool 180 and/or another portion of the BHA 124 may also comprise a downhole controller 188 operable to receive, process, and/or store information received from the surface equipment 110, downhole sensors 184, and/or other portions of the BHA 124. The controller 188 may also store executable computer programs (e.g., program code instructions), including for implementing one or more aspects of the operations described herein. The downhole sensors 184 may be operable to acquire downhole measurement data associated with and/or indicative of the BHA 124, the wellbore 102, and/or the formation 106. The downhole sensors 184 may comprise an inclination sensor, a rotational position sensor, and/or a rotational speed sensor, which may include one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and/or other sensors for determining the orientation, position, and/or speed of one or more portions of the BHA 124 (e.g., the drill bit 126, the downhole tool 180, the mud motor 182) and/or other portions of the tool string 120 relative to the wellbore 102 and/or the wellsite surface 104. The downhole sensors 184 may comprise a depth correlation tool for determining and/or logging position (i.e., depth) of one or more portions of the BHA 124 and/or other portions of the tool string 120 within the wellbore 102 and/or with respect to the wellsite surface 104.

The telemetry system 200 may also comprise one or more mud-pulse telemetry signal sensors 210 disposed in association with one or more portions of a fluid circulation system 202. The drilling fluid circulation system 202 may be operable to circulate the drilling fluid between the surface equipment 110 and the drill bit 126 during drilling operations. For example, the drilling fluid circulation system 202 may be operable to inject the drilling fluid from the wellsite surface into the wellbore 102 via an internal fluid passage (e.g., the internal fluid passage 121 shown in FIG. 1) extending longitudinally through the drill string 120. The drilling fluid circulation system 202 may comprise a pit, a tank, and/or other fluid container (e.g., the fluid container 142 shown in FIG. 1) holding the drilling fluid (i.e., mud), and one or more drilling fluid pumps 144 (i.e., mud pumps) operable to transfer the drilling fluid from the container into the wellbore 102. The drilling fluid may be drawn from the container via a suction fluid conduit 212 and distributed among the pumps 144 via a suction manifold or another common suction conduit 214. The drilling fluid may be discharged from the pumps 144 into a discharge manifold or another common discharge conduit 216 and transferred to a top drive 116 via a fluid conduit 145 (e.g., a stand pipe). The drilling fluid 140 may then flow through an internal passage of the top drive 116 into the internal fluid passage of the drill string 120. The drilling fluid may continue to flow downhole through the internal passage of the drill string 120, as indicated by directional arrow 158. The drilling fluid may exit the BHA 124 via ports 128 in the drill bit 126 and then circulate uphole through an annular space 108 of the wellbore 102 defined between an exterior of the drill string 120 and the sidewall of the wellbore 102, such flow being indicated by directional arrows 159.

One or more of the mud-pulse telemetry signal sensors 210 may be installed or otherwise disposed along one or more fluid conduits fluidly connecting the drilling fluid pumps 114 to the top drive 116. For example, one or more of the sensors 210 may be disposed near or adjacent to the top drive 116 at or near an upper (top) end of the fluid conduit 145 for passing (i.e., transferring) drilling fluid from drilling fluid pumps 144 to the top drive 116. One or more of the sensors 210 may also or instead be disposed near or adjacent to the pumps 144 at or near a lower (bottom) end of the fluid conduit 145. One or more of the telemetry signal sensors 210 may also or instead be disposed closer to fluid outlets of the pumps 144 along the fluid conduit 216 fluidly connecting the pumps 144 with the fluid conduit 145.

The mud-pulse telemetry signal 206 transmitted by the downhole telemetry device 204 may be or comprise pressure pulses or fluctuations sent through the drilling fluid flowing downhole within the fluid passage of the drill string 120, the fluid passage of the top drive 116, and the fluid conduits 145, 216. For example, the downhole telemetry device 204 may comprise a modulator selectively operable to cause pressure pulses in the drilling fluid flowing downhole. During telemetry operations, the downhole telemetry device 204 may modulate the pressure of the drilling fluid flowing downhole to transmit downhole data (e.g., uplink mud-pulse telemetry data) received from the controller 188, the downhole sensors 184, and/or other portions of the BHA 124 in the form of the pressure pulses. The telemetry signal 206 (i.e., modulated pressure pulses or waves) then travel uphole along the drilling fluid through the fluid passage, the top drive 116, and the fluid conduits 145, 216 to be received (e.g., detected, sensed) by one or more of the telemetry signal sensors 210. Thus, one or more of the telemetry signal sensors 210 may be or comprise dynamic pressure transducers or sensors operable to receive or sense the telemetry signal 206 in the form of pressure pulses or waves propagating along the drilling fluid flowing within corresponding fluid conduits 145, 216. Each sensor 210 may then generate or otherwise output an output signal (i.e., raw telemetry data) comprising a signature (e.g., characteristics, waveform, frequency, amplitude, etc.) of the telemetry signal 206, which in turn comprises, contains, or is indicative of the downhole data transmitted by the downhole telemetry device 204. Namely, each sensor 210 may be operable to convert the telemetry signal 206 having the form of pressure pulses or waves, to an electrical output signal comprising the telemetry signal signature. A telemetry signal processor 220 (i.e., a demodulator) may receive the telemetry signal signature and demodulate, reconstruct, or otherwise ascertain the downhole data from the telemetry signal signature.

An equipment controller 222 may receive the downhole data from the telemetry signal processor 220. The equipment controller 222 may also or instead receive the telemetry signal signature from the telemetry signal processor 220 and/or telemetry signal sensors 210. The equipment controller 222 may cause the telemetry signal signature and/or the downhole data to be displayed to rig personnel. The equipment controller 222 may also or instead analyze the telemetry signal signature and/or the downhole data to monitor and control telemetry operations and/or the well construction operations based on the telemetry signal signature and/or the downhole data. The sensors 210 may be communicatively connected with the telemetry signal processor 220 and/or the equipment controller 222 via wired and/or wireless communication means 218. The telemetry signal processor 220 may be communicatively connected with the equipment controller 222 via wired and/or wireless communication means 224.

The equipment controller 222 may be or comprise a programmable logic controller (PLCs), a computer (PCs), an industrial computer (IPC), or other equipment controller equipped with control logic. The equipment controller 222 may be or comprise a portion of a rig control system operable to monitor and control one or more pieces of the well construction equipment of the well constriction system, such as the well construction system 100 shown in FIG. 1. For example, the equipment controller 222 may be or comprise a direct control device, such as a PLC, communicatively connected with and operable to control one or more pieces of equipment of the well construction system. The equipment controller 222 may be imparted with and operable to execute program code instructions, such as rigid computer programing. Such equipment controller 222 may be a local control device disposed in association with the one or more pieces of equipment. The equipment controller 222 may also or instead be or comprise a coordinated control device, such as a PC, an IPC, and/or another processing device. The equipment controller 222 may be imparted with and operable to execute program code instructions, including high level programming languages, such as C, and C++, among other examples, and may be used with program code instructions running in a real-time operating system (RTOS). Such equipment controller 222 may be a system-wide control device communicatively connected with and operable to control a plurality of devices and/or subsystems of the well construction system. The equipment controller 222 may be or form at least a portion of the controller 192 shown in FIG. 1.

FIG. 3 is a schematic view of at least a portion of an example implementation of a telemetry system 250 for transmitting a telemetry signal 256 from a BHA 124 located downhole to surface equipment 110 according to one or more aspects of the present disclosure. The telemetry system 250 may form a portion of or operate in conjunction with the well construction system 100 shown in FIG. 1 and, thus, may comprise one or more features of the well construction system 100, including where indicated by the same reference numbers. The telemetry system 250 may comprise one or more features of the telemetry system 200 shown in FIG. 2, including where indicated by the same reference numbers. Accordingly, the following description refers to FIGS. 1-3, collectively.

The telemetry system 250 may comprise a downhole electromagnetic telemetry device 254 (e.g., an electromagnetic signal transmitter) installed or otherwise disposed within a BHA 124 of a drill string 120 extending within a wellbore 102 and operable to communicate with surface equipment 110 via electromagnetic telemetry. For example, the downhole telemetry device 254 may be operable to transmit the electromagnetic telemetry signal 256 (e.g., a voltage, a current, an electromagnetic field) uphole through a rock formation 106 through which the wellbore 102 extends between the BHA 124 and a wellsite surface 104, to transmit downhole data to the surface equipment 110. The telemetry device 254 may be located within a downhole tool 180 of the BHA 124, which may further comprise a mud motor 182 and a drill bit 126. The downhole tool 180 and/or another portion of the BHA 124 may also comprise a downhole controller 188 operable to receive, process, and/or store information received from the surface equipment 110, downhole sensors 184, and/or other portions of the BHA 124.

The telemetry system 250 may also comprise one or more electromagnetic telemetry signal sensors 260 (e.g., electromagnetic telemetry signal receivers, probes, or ground antennas) extending at least partially into the ground at the wellsite surface 104. For example, the signal sensors 260 may be distributed at the wellsite surface 104 at various locations and distances around the wellbore 102. The electromagnetic telemetry signal 256 transmitted by the downhole telemetry device 254 may be or comprise electromagnetic waves sent through the rock formation comprising downhole data (e.g., uplink electromagnetic telemetry data) received from the downhole controller 188, the downhole sensors 184, and/or other portions of the BHA 124. The telemetry signal 256 then travels to the wellsite surface 104 through the rock formation 106 to be received (e.g., detected, sensed) by one or more of the telemetry signal sensors 260. Each sensor 260 may then generate or otherwise output an output signal (i.e., raw telemetry data) comprising a signature (e.g., characteristics, waveform, frequency, amplitude, etc.) of the telemetry signal 256, which in turn comprises, contains, or is indicative of the downhole data transmitted by the downhole telemetry device 254. Namely, each sensor 260 may be operable to convert the telemetry signal 256 having the form of electromagnetic waves, to an electrical output signal comprising the telemetry signal signature. A telemetry signal processor 270 may receive the telemetry signal signature and demodulate, reconstruct, or otherwise ascertain the downhole data from the telemetry signal signature.

An equipment controller 222 may receive the downhole data from the telemetry signal processor 270. The equipment controller 222 may also or instead receive the telemetry signal signature from the telemetry signal processor 270 and/or telemetry signal sensors 210. The equipment controller 222 may cause the telemetry signal signature and/or the downhole data to be displayed to rig personnel. The equipment controller 222 may also or instead analyze the telemetry signal signature and/or the downhole data to monitor and control telemetry operations and/or the well construction operations based on the telemetry signal signature and/or the downhole data. The sensors 260 may be communicatively connected with the telemetry signal processor 270 and/or the equipment controller 222 via wired and/or wireless communication means 268. The telemetry signal processor 270 may be communicatively connected with the equipment controller 222 via wired and/or wireless communication means 224.

FIG. 4 is a schematic view of at least a portion of an example implementation of a processing device 300 (or system) according to one or more aspects of the present disclosure. The processing device 300 may be or form at least a portion of one or more processing devices, equipment controllers, and/or other electronic devices shown in one or more of the FIGS. 1-3. Accordingly, the following description refers to FIGS. 1-4, collectively.

The processing device 300 may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, PCs (e.g., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, IPCs, PLCs, servers, internet appliances, and/or other types of computing devices. The processing device 300 may be or form at least a portion of the surface equipment controller 192 shown in FIG. 1. The processing device 300 may further be or form at least a portion of the downhole controller 188 shown in FIGS. 1-3. The processing device 300 may also be or form at least a portion of the telemetry signal processors 220, 270 and the equipment controller 222 shown in FIGS. 2 and 3. Although it is possible that the entirety of the processing device 300 is implemented within one device, it is also contemplated that one or more components or functions of the processing device 300 may be implemented across multiple devices, some or an entirety of which may be at the wellsite and/or remote from the wellsite.

The processing device 300 may comprise a processor 312, such as a general-purpose programmable processor. The processor 312 may comprise a local memory 314, and may execute machine-readable and executable program code instructions 332 (i.e., computer program code) present in the local memory 314 and/or another memory device. The processor 312 may execute, among other things, the program code instructions 332 and/or other instructions and/or programs to implement the example methods, processes, and/or operations described herein. For example, the program code instructions 332, when executed by the processor 312 of the processing device 300, may cause the equipment controllers 192, 222 to perform example methods, processes, and/or operations described herein. The program code instructions 332, when executed by the processor 312 of the processing device 300, may also or instead cause the processor 312 to receive and analyze telemetry signal profiles (e.g., raw telemetry data), and output control commands to one or more pieces of well construction equipment and/or telemetry devices 204, 254 based on the analyzed telemetry signal profiles.

The processor 312 may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Examples of the processor 312 include one or more INTEL microprocessors, microcontrollers from the ARM and/or PICO families of microcontrollers, embedded soft/hard processors in one or more FPGAs.

The processor 312 may be in communication with a main memory 316, such as may include a volatile memory 318 and a non-volatile memory 320, perhaps via a bus 322 and/or other communication means. The volatile memory 318 may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory 320 may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 318 and/or non-volatile memory 320.

The processing device 300 may also comprise an interface circuit 324, which is in communication with the processor 312, such as via the bus 322. The interface circuit 324 may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others. The interface circuit 324 may comprise a graphics driver card. The interface circuit 324 may comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.).

The processing device 300 may be in communication with various sensors, video cameras, actuators, processing devices, equipment controllers, and other devices of the well construction system via the interface circuit 324. The interface circuit 324 can facilitate communications between the processing device 300 and one or more devices by utilizing one or more communication protocols, such as an Ethernet-based network protocol (such as ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 communication, or the like), a proprietary communication protocol, and/or another communication protocol.

One or more input devices 326 may also be connected to the interface circuit 324. The input devices 326 may permit the rig personnel (e.g., a driller) to enter the program code instructions 332, which may be or comprise control commands, operational parameters, operational thresholds, and/or other operational set-points. The program code instructions 332 may further comprise modeling or predictive routines, equations, algorithms, processes, applications, and/or other programs operable to perform example methods, calculations, and/or operations described herein. The input devices 326 may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples. One or more output devices 328 may also be connected to the interface circuit 324. The output devices 328 may permit for visualization or other sensory perception of various data, such as sensor data, status data, and/or other example data. The output devices 328 may be, comprise, or be implemented by video output devices (e.g., an LCD, an LED display, a CRT display, a touchscreen, etc.), printers, and/or speakers, among other examples. The one or more input devices 326 and the one or more output devices 328 connected to the interface circuit 324 may, at least in part, facilitate the HMIs described herein.

The processing device 300 may comprise a mass storage device 330 for storing data and program code instructions 332. The mass storage device 330 may be connected to the processor 312, such as via the bus 322. The mass storage device 330 may be or comprise a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples. The processing device 300 may be communicatively connected with an external storage medium 334 via the interface circuit 324. The external storage medium 334 may be or comprise a removable storage medium (e.g., a CD or DVD), such as may be operable to store data and program code instructions 332.

As described above, the program code instructions 332 and other data (e.g., sensor data or measurements database) may be stored in the mass storage device 330, the main memory 316, the local memory 314, and/or the removable storage medium 334. Thus, the processing device 300 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor 312. In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code instructions 332 (i.e., software or firmware) thereon for execution by the processor 312. The program code instructions 332 may include program instructions or computer program code that, when executed by the processor 312, may perform and/or cause performance of example methods, calculations, processes, and/or operations described herein.

During well construction operations (e.g., drilling operations), the telemetry sensors 210, 260 described above and shown in FIGS. 2 and 3 may be further operable to receive, pick up, sense, or otherwise detect vibrational (e.g., acoustic), and electrical and electromagnetic rig noise, respectively, generated by the various pieces of well construction equipment, in addition to the respective mud-pulse and electromagnetic telemetry signals. For example, the telemetry sensors 210, 260 may be operable to detect vibrations and/or electromagnetic waves, respectively, that are generated by the well construction equipment shown in FIGS. 1-3, such as the top drive 116, the drawworks 118, drilling fluid pumps 144, the drill bit 126, and other well construction equipment, comprising, for example, rotary actuators (e.g., motors, engines), linear actuators (e.g., hydraulic cylinders), and/or electromagnetic actuators. The rig noise generated by the well construction equipment may propagate from the well construction equipment along the ground 104, 106, the ambient air, and various portions of the well construction system (e.g., the conveyance means 122, the support structure 112, the drill floor 114, the fluid conduits 145, 216, etc.) to the sensors 210, 260. The sensors 210, 260 may each output an electrical signal containing a telemetry signal signature based on or otherwise indicative of the detected telemetry signal and a plurality of rig noise signatures based on or otherwise indicative of the detected rig noise generated by the well construction equipment. The electrical signal containing the telemetry signal signature and the rig noise signatures generated by each sensor 210, 260 may then be received by an equipment controller (e.g., the equipment controller 222, the processing device 300) from the telemetry signal processor 220, 270 and/or directly from the sensors 210, 260. However, when rig noise interferes with the telemetry signal 206, 256, the telemetry signal processor 220, 270 and/or the equipment controller may be unable to distinguish or discern the telemetry signal signatures from one or more rig noise signatures.

The equipment controller may record and/or analyze the telemetry signal signature, along with the rig noise signatures output by the sensors 210, 260. The equipment controller may then output control commands (e.g., control signals or data) to change operational parameters of well construction equipment based on the telemetry signal signature and rig noise signatures to prevent, minimize, or otherwise reduce interference to the telemetry signal 206, 256 by the rig noise. The equipment controller may also or instead output control commands to change operational parameters of the telemetry system 200, 250 based on the telemetry signal signature and rig noise signatures to reduce interference to the telemetry signal 206, 256 by the rig noise. The equipment controller may also or instead transmit the telemetry signal signature and the rig noise signatures to a video output device (e.g., a video output device 196 shown in FIG. 1) or otherwise cause the telemetry signal signature and rig noise signatures to be displayed on the video output device for viewing by rig personnel (e.g., a driller). The rig personnel may then cause the equipment controller to output control commands to change operational parameters or operation sequences of the well construction equipment based on the displayed telemetry signal signature and rig noise signatures to reduce interference to the telemetry signal 206, 256 by the rig noise, and/or to change operational parameters of the telemetry system 200, 250 based on the displayed telemetry signal signature and rig noise signatures to reduce interference to the telemetry signal 206, 256 by the rig noise.

FIG. 5 is a graph 400 (e.g., a frequency spectrogram) showing example rig noise signatures 402 and telemetry signal signature 404 contained within a sensor signal output by one or more of the sensors 210, 260 shown in FIGS. 2 and 3 according to one or more aspects of the present disclosure. The rig noise signatures 402 are indicative of rig noise generated by various well construction equipment of a well construction system 100 shown in FIGS. 1-3, and the telemetry signal signature 404 is indicative of a telemetry signal 206, 256 generated by a telemetry device 204, 254 shown in FIGS. 2 and 3, respectively. The rig noise signatures 402 and the telemetry signal signature 404 may each be a component of a raw electrical (e.g., digital or analog) sensor signal generated by one or more of the sensors 210, 260. The rig noise signatures 402 and the telemetry signal signature 404 (e.g., raw telemetry data) may each be or comprise an acoustic or electromagnetic signature indicative of characteristics (e.g., waveform, amplitude, frequency) of an acoustic or electromagnetic rig noise and the telemetry signals 206, 256, respectively. Frequency (e.g., Hertz (Hz)) of the rig noise signatures 402 and telemetry signal signature 404 are shown plotted along the vertical axis, with respect to time (e.g., seconds), which is shown plotted along the horizontal axis. The graph 400 may be generated by a processing device (e.g., the equipment controller 222, the processing device 300) and output to a visual (e.g., video) output device (e.g., the video output device 196). The following description refers to FIGS. 1-5, collectively.

An equipment controller (e.g., the equipment controller 222, the processing device 300) within the scope of the present disclosure may be operable to control one or more pieces of the well construction equipment generating the rig noise based on information indicative of a telemetry signal 206, 256 and rig noise to improve the quality (e.g., distinguishability, discernibility) of the telemetry signal 206, 256 with respect to the rig noise and, thus, improve efficiency of downhole telemetry. For example, the equipment controller may be operable to analyze the telemetry signal signature 404 and the rig noise signatures 402 to determine characteristics of the telemetry signal 206, 256 and the rig noise, respectively, and determine if the rig noise interferes with the telemetry signal 206, 256. The equipment controller may then control the telemetry device 204, 254 and/or one or more pieces of the well construction equipment based on the analyzed telemetry signal signature 404 and rig noise signatures 402 to reduce interference by the rig noise to the telemetry signal 206, 256. The equipment controller may also record the telemetry signal signature 404 and the rig noise signatures 402.

Before the telemetry device 204, 254 and/or one or more pieces of the well construction equipment can be controlled to reduce interference by the rig noise to the telemetry signal 206, 256, a relationship between each piece (or instance) of the well construction equipment and the rig noise that each such piece of well construction equipment generates may be determined. Namely, rig noise generated by well construction equipment may be detected and converted to a plurality of rig noise signatures 402 by the sensors 210, 260, and then each rig noise signature 402 may be associated with a corresponding piece of well construction equipment (and/or with an operational parameter or state of the corresponding piece of well construction equipment), thereby determining a relationship (i.e., an association) between each piece of construction equipment (and/or each operational parameter or state of each piece of well construction equipment) and a corresponding rig noise signature 402.

For example, various well construction (e.g., drilling) operations or testing operations (i.e., test runs) may be performed by the well construction equipment, thereby generating corresponding rig noise that is detected by the sensors 210, 260. The well construction operations and the testing operations may be performed by the well construction equipment when telemetry operations are not performed by the telemetry devices 204, 254. Each rig noise signature 402 may be output (e.g., generated) by the sensor 210, 260 and recorded and/or analyzed by the equipment controller in association with a corresponding piece of well construction equipment to determine the equipment to noise relationship between each noise signature 402 and piece of well construction equipment. The rig noise signatures 402 may be output, recorded, and/or analyzed during different phases of well construction or testing operations (e.g., equipment operating and/or stopped, equipment in open and/or closed positions, equipment moving pipes, equipment at different depths, etc.) to determine a full or otherwise comprehensive profile (i.e., historical data) of the equipment to noise relationship between the well construction equipment (and/or the operational parameters or operational states) and corresponding rig noise signatures 402. The determined and recorded equipment to noise relationship (or associations) may be used to determine if planned or current well construction operations will cause rig noise that can cause interference to the telemetry signal 206, 256. Thus, if a planned parallel operation (e.g., offline stand-building) generates rig noise that interferes with the telemetry operations, the equipment controller may automatically adjust the planned operation sequence (such as by swapping such sequence with another sequence, or delaying the start of the sequence, etc.), such that this planned operation sequence doesn't happen at the same as the telemetry operations.

The equipment to noise relationship may be indicative of which pieces of well construction equipment and/or which stages of well construction operations generate rig noise that interferes with the telemetry operations and to what extent or degree, such as by examining which rig noise signature 402 (and thus which piece of equipment) has a frequency range that overlaps with a frequency range of the telemetry signal signature 404. The rig noise signatures 402 and the telemetry signal signature 404 may be further indicative of relative amplitude of the overlapping frequency ranges. The rig noise signatures 402 may be further indicative of which type and location of the telemetry signal sensors 210, 260 result in less interfering rig noise being captured by the sensors 210, 260 along with the telemetry signals 206, 256 and during which stages of the well construction operations. The equipment controller and/or other portions of the rig control system may use the rig noise signatures 402, the telemetry signal signature 404, and the equipment to noise relationship as a basis for automatically controlling the well construction equipment generating the corresponding rig noise and/or to control the telemetry devices 204, 254 to execute or otherwise implement telemetry operations while reducing interference to the telemetry signal 206, 256 by the rig noise. Based on the rig noise signatures 402, the telemetry signal signature 404, and the equipment to noise relationship, the equipment controller may be operable to determine which well construction equipment to control, determine how to control the telemetry devices 204, 254, determine the optimal time to start or stop telemetry operations, and/or determine optimal time to start or stop selected well construction operations performed by the well construction equipment to reduce interference to the telemetry signal 206, 256 by the rig noise and, thus, optimize efficiency of the telemetry operations. Based on such determinations, the equipment controller may then automatically control the well construction equipment generating the corresponding rig noise and/or control the telemetry devices 204, 254 to reduce interference to the telemetry signal 206, 256 by the rig noise.

An equipment controller within the scope of the present disclosure may receive and analyze in real-time current rig noise signatures 402 (i.e., real-time data) output by the sensors 210, 260 during well construction operations and control well construction equipment generating the rig noise based on the current rig noise signatures 402 and on the previously determined equipment to noise relationship. For example, the equipment controller may change operational parameters of the well construction equipment associated with the received rig noise signatures 402 such that frequency ranges of the rig noise signatures 402 do not overlap (i.e., are the same or close) with a frequency range of the telemetry signal signature 404 (i.e., an operating frequency range of the telemetry device 204, 206). Namely, the equipment controller may change operational parameters (e.g., position, speed, oscillation rate, operating frequency, etc.) of a piece of well construction equipment that generates a rig noise signature 402 that overlaps with a frequency range of (and happens at the same time as) the telemetry signal signature 404. As shown in graph 400, the frequency of a rig noise signature 406 associated with a piece of well construction equipment may be increased automatically by the equipment controller by changing operational parameters of the piece of well construction equipment to shift 408 the rig noise signature 406 from its original frequency of about 14 Hz, identified by reference number 416, to its new frequency of about 18 Hz, identified by reference number 418, thereby eliminating or reducing interference caused by rig noise associated with the rig noise signature 406 to the telemetry signal 206, 256 associated with the telemetry signal signature 404. The equipment controller may also or instead change starting and/or stopping operating time of the well construction equipment causing the rig noise, such that the telemetry operations (with telemetry signal signature 404) do not happen at the same time when the rig noise signatures 402 are present. For example, the equipment controller may change starting and/or stopping operating time of the well construction equipment that generates a rig noise signature 410 having a frequency that overlaps with a frequency range of the telemetry signal signature 404. As further show in graph 400, the equipment controller may automatically stop operations of a piece of well construction equipment associated with the rig noise signature 410, having a frequency ranging between about 14 and 15 Hz, at a time of about 750 seconds, identified by reference number 420, right before the telemetry device 204, 254 starts operating at the frequency ranging between about 13 and 15 Hz, thereby eliminating or reducing interference caused by rig noise associated with the rig noise signature 410 to the telemetry signal 206, 256 associated with the telemetry signal signature 404.

The equipment controller may also or instead change the operational parameters of the telemetry system 200, 250 such that a frequency range of the telemetry signal signature 404 does not overlap with frequency ranges of one or more of the rig noise signatures 402. Namely, the equipment controller may change an operating frequency range (e.g., telemetry signal transmission rate, mud-pulse transmission rate, electromagnetic wave transmission rate) of the telemetry device 204, 254, such that the frequency range of the telemetry signal signature 404 does not overlap with frequency ranges of one or more of the rig noise signatures 402. As further shown in graph 400, the operating frequency of the telemetry device 204, 254 associated with the telemetry signal signature 404 may be automatically increased by the equipment controller to shift 412 the telemetry signal signature 404 from its original operating frequency ranging between about 8 Hz and 10 Hz and centered at about 9 Hz, identified by reference number 422, to its new operating frequency ranging between about 13 and 15 Hz and centered at about 14 Hz, identified by the reference number 416, thereby eliminating or reducing interference caused by rig noise associated with rig noise signature 414 to the telemetry signal 206, 256 associated with the telemetry signal signature 404. The equipment controller may also or instead change starting and/or stopping operating times of the telemetry device 204, 254 having an operating frequency that overlaps with frequency of the rig noise, such that the telemetry operations (with telemetry signal signature 404) do not happen at the same time when the rig noise signatures 402 are present. As further shown in graph 400, the equipment controller may automatically start operations of the telemetry device 204, 254 associated with the telemetry signal signature 404, at a time of about 750 seconds, identified by the reference number 420, right after the piece of well construction equipment associated with the rig noise signature 410 stops operating, thereby eliminating or reducing interference caused by rig noise associated with the rig noise signature 410 to the telemetry signal 206, 256 associated with the telemetry signal signature 404.

In circumstances when rig noise frequencies cover or otherwise overlap with substantially every frequency range usable by the telemetry devices 204, 254 to perform telemetry operations, the equipment controller may change order and/or timing of telemetry operations and/or selected well construction operations such that the telemetry signals 206, 256 (and corresponding telemetry signal signature 404) are not being transmitted at the same time when interfering rig noise (and corresponding rig noise signatures 402) is being generated. Thus, as described above, the equipment controller may change starting and/or stopping operating times of the telemetry device 204, 254 and/or change the operation sequences of well construction equipment generating a rig noise signature 402 that overlaps with frequency range of the telemetry device 204, 254, such that the telemetry device 204, 254 and the well construction equipment generating the interfering rig noise do not operate at the same time.

The equipment controller may also or instead filter out rig noise signatures 402 having frequency ranges that overlap with frequency range of the telemetry signal signature 404. For example, the equipment controller may monitor frequency ranges of rig noise signatures 402 and, if frequency ranges of one or more rig noise signatures 402 overlap with frequency range of the telemetry signal signature 404, then the equipment controller may apply a signal filter to filter out such rig noise signatures 402. The frequency ranges of rig noise signatures 402 may be determined or otherwise known before initiating operations of the corresponding well construction equipment based on the saved or otherwise previously determined equipment to noise relationship.

When a pending telemetry operation coincides with a planned operation sequence (or equipment operational states) that generates rig noise that interferes with a telemetry signal 206, 256, operations (e.g., operation sequence, operational state, operational parameters) of the well construction equipment may be changed automatically to facilitate telemetry operations. For example, an equipment controller (e.g., the equipment controller 222 or another processing device) within the scope of the present disclosure may be further operable to receive, store, and/or analyze a digital well construction plan (i.e., a well construction, drilling, or job plan in the form of a computer program code) and to automatically execute the digital well construction plan to perform well construction operation, such as to trip in a drill string from depth A to depth B, or to drill from depth C to depth D, with simultaneous operations performed by multiple pieces of well construction equipment (i.e., rig equipment), including telemetry operations. The equipment controller may compare the planned telemetry operations with other concurrent planned well construction operations based on the equipment to noise relationship to determine if certain planned well construction operations will generate rig noise that will interfere with the telemetry signal 206, 256 of the planned telemetry operations. If the equipment controller determines that certain planned well construction operations will generate rig noise that will interfere with the telemetry signal 206, 256 of the planned telemetry operations, the equipment controller may automatically change the digital well construction plan to prevent, minimize, or otherwise reduce interference to the telemetry signal 206, 256 by the rig noise before execution of the digital well construction plan. Namely, the equipment controller may adjust or otherwise change the operational parameters or timing of the planned telemetry operations and/or certain planned well construction operation sequences to reduce interference to the telemetry signal 206, 256 by the rig noise during the planned telemetry operations.

The equipment controller may change the digital well construction plan by changing operational parameters or timing of the telemetry operations and/or well construction operation sequences to minimize interruptions by or effect of rig noise on the telemetry operations. For example, the equipment controller may change the digital well construction plan to inhibit operation or change timing of operations of a selected one or more of the well construction equipment and/or the telemetry devices 204, 254 to reduce interference to the telemetry signal 206, 256 by the rig noise. Namely, the equipment controller may be operable to automatically determine the optimal time to start or stop the telemetry operations and/or optimal time to start or stop well construction operation sequences to minimize interference by the rig noise with the telemetry signals 206, 256 during telemetry operations. The equipment controller may change the digital well construction plan to stop or change operational parameters (e.g., speed, power, frequency, amplitude, etc.) of a piece of well construction equipment that causes rig noise that interferes with the telemetry signal 206, 256 right before the telemetry operations start. The equipment controller may also or instead change the digital well construction plan to stop telemetry operations right before a piece of well construction equipment that causes a relatively high amount of rig noise or interferes with the telemetry signal 206, 256 starts operating. The equipment controller may also or instead change the digital well construction plan to start the telemetry operations right after a piece of well construction equipment that causes the rig noise that interferes with the telemetry signal 206, 256 stops operating.

Current rig noise signatures 402 output by the telemetry sensors 210, 260 and/or current telemetry signal signature 404 associated with the telemetry device 204, 254 may be displayed in real-time to a rig personnel (e.g., the driller) via one or more of the output devices 196 of the control workstation 197 to assist the rig personnel to manually operate the control workstation 197 to: (1) change operational parameters of the well construction equipment based on the rig noise signatures 402 and telemetry signal signature 404 displayed on the one or more of the video output devices 196 to reduce interference to the telemetry signal by the rig noise; (2) change operational parameters of the telemetry system 200, 250 based on the determined equipment to noise relationship and the telemetry signal signature 404 and/or rig noise signatures 402 displayed on the video output device 196 to reduce interference to the telemetry signal by the rig noise; and/or (3) change operation sequence of a well construction plan such that telemetry operation do not occur at the same time as operations of well construction equipment that generate rig noise that interfere with the telemetry signal 206, 256.

The graph 400 shown in FIG. 5 may be or comprise an example display screen of a video output device 196 of the control workstation 197 showing rig noise signatures 402 and a telemetry signal signature 404 to a rig personnel to assist the rig personnel to manually operate the control workstation 197 to change operational parameters of the well construction equipment and/or the telemetry system 200, 250. The previously determined equipment to noise relationship (or associations) may be displayed to and used by the rig personnel to determine which pieces of well construction equipment and/or which stages of well construction operations generate rig noise signatures 402 that overlap in frequency and take place at the same time as and, thus, interfere with the telemetry signal signature 404. The equipment to noise relationship between each instance of the well construction equipment and the corresponding instance of the rig noise signature 402 may be displayed on the video output device for viewing by the rig personnel. For example, the video output device may display a list of each instance of the well construction equipment adjacent a frequency range of each corresponding rig noise signature 402 caused by that instance of the well construction equipment. The video output device may also or instead display a name or another identifier of each piece of well construction equipment along the vertical axis of the graph 400 or otherwise in association with each displayed rig noise signature 402.

The displayed rig noise signatures 402, the current telemetry signal signature 404, and the previously determined equipment to noise relationship may aid the rig personnel to determine which well construction equipment generates rig noise that can interfere with telemetry operations, determine how to control the well construction equipment to reduce interference by the rig noise, determine how to control the telemetry devices 204, 254 to reduce interference by the rig noise, determine an optimal time to start or stop telemetry operations to reduce interference by the rig noise, and/or determine an optimal time to start or stop selected well construction operations to reduce interference by the rig noise. Based on such determinations, the rig personnel may then manually control the well construction equipment generating the rig noise and/or the telemetry devices 204, 254 via the control workstation 197 to reduce interference by the rig noise and, thus, optimize efficiency of the telemetry operations.

For example, the rig personnel may change the operational parameters of the well construction equipment such that a frequency range of the rig noise (and the rig noise signatures 402) does not overlap with a frequency range of the telemetry signals 206, 256 (and the telemetry signal signature 404). Namely, the rig personnel may change an operating parameter (e.g., rotational speed, oscillation rate, operating frequency) of a piece of well construction equipment that generates a rig noise signature 402 that overlaps with a frequency range of the telemetry signal signature 404. As shown in graph 400, frequency of the telemetry signal signature 404 ranges between about 13 and 15 Hz, and is centered at about 14 Hz. Thus, the operating parameter of a piece of well construction equipment associated with a rig noise signature 406 may be changed (e.g., increased) to shift 408 the rig noise signature 406 from its original frequency of about 14 Hz, identified by reference number 416, to its new frequency of about 18 Hz, identified by reference number 418, thereby eliminating or reducing interference caused by rig noise associated with the rig noise signature 406 to the telemetry signal 206, 256 associated with the telemetry signal signature 404.

The rig personnel may also or instead change starting and/or stopping operating time of the piece of well construction equipment that generates the interfering rig noise associated with the rig noise signature 410 such that that piece of well construction equipment does not operate at the same time the telemetry signal 206, 256 associated with the telemetry signal signature 404 is being transmitted. As further shown in graph 400, the rig personnel may stop operations of a piece of well construction equipment associated with the rig noise signature 410, having a frequency ranging between about 14 and 15 Hz, at a time of about 750 seconds, identified by reference number 420, right before the telemetry device 204, 254 starts operating at the frequency ranging between about 13 and 15 Hz, thereby eliminating or reducing interference caused by rig noise associated with the rig noise signature 410 to the telemetry signal 206, 256 associated with the telemetry signal signature 404.

The rig personnel may also or instead change the operational parameters of the telemetry system 200, 250 such that a frequency range of the telemetry signal signature 404 does not overlap with frequency ranges of one or more of the rig noise signatures 402. Namely, the rig personnel may change an operating frequency range (e.g., telemetry signal transmission rate, mud-pulse transmission rate, electromagnetic wave transmission rate) of the telemetry device 204, 254, such that the frequency range of the telemetry signal signature 404 does not overlap with frequency ranges of one or more of the rig noise signatures 402. As further shown in graph 400, the operating frequency of the telemetry device 204, 254 associated with the telemetry signal signature 404 may be increased to shift 412 the telemetry signal signature 404 from its original operating frequency ranging between about 8 Hz and 10 Hz and centered at about 9 Hz, identified by reference number 422, to its new operating frequency ranging between about 13 and 15 Hz and centered at about 14 Hz, identified by the reference number 416, thereby eliminating or reducing interference caused by rig noise associated with rig noise signature 414 to the telemetry signal 206, 256 associated with the telemetry signal signature 404.

The rig personnel may also or instead change starting and/or stopping operating times of the telemetry device 204, 254, such that the telemetry signal 206, 256 associated with the telemetry signal signature 404 is not being transmitted at the same time that a piece of well construction equipment that generates the interfering rig noise associated with the rig noise signature 410 is being operated. As further shown in graph 400, the rig personnel may start operations of the telemetry device 204, 254 associated with the telemetry signal signature 404, at a time of about 750 seconds, identified by the reference number 420, right after the piece of well construction equipment associated with the rig noise signature 410 stops operating, thereby eliminating or reducing interference caused by rig noise associated with the rig noise signature 410 to the telemetry signal 206, 256 associated with the telemetry signal signature 404.

In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising: (A) a telemetry system of a drilling rig, wherein the telemetry system comprises: (i) a transmitter carried by a drill string and operable to transmit a telemetry signal; and (ii) a receiver included in surface equipment of the drilling rig and operable to generate an output signal comprising: (a) a telemetry signal signature based on the telemetry signal; and (b) a rig noise signature based on rig noise generated by rig equipment of the drilling rig; and (B) an equipment controller comprising a processor and a memory storing computer program code, wherein the equipment controller is operable to automatically reduce interference by the rig noise with the telemetry signal by outputting control commands to change operational parameters of the rig equipment and/or the telemetry system.

The telemetry signal may comprise at least one of a mud-pulse telemetry signal and electromagnetic telemetry signal.

The telemetry signal signature may be indicative of frequency of the telemetry signal and the rig noise signature may be indicative of frequency of the rig noise.

The receiver may be or comprise a pressure sensor, the telemetry signal may comprise pressure fluctuations propagating through drilling fluid flowing within the drill string and the surface equipment, the receiver may be further operable to receive the telemetry signal and the rig noise, and the output signal may be an electrical signal comprising the telemetry signal signature and the rig noise signature.

The receiver may be or comprise an electromagnetic signal sensor, the telemetry signal may comprise an electromagnetic signal transmitted through rock formation extending between the transmitter and the receiver, the receiver may be further operable to receive the telemetry signal and the rig noise, and the output signal may be an electrical signal comprising the telemetry signal signature and the rig noise signature.

Changing the operational parameters of the rig equipment may comprise changing the operational parameters of the rig equipment such that a frequency range of the rig noise signature does not overlap with a frequency range of the telemetry signal signature.

Changing the operational parameters of the rig equipment may comprise changing starting and/or stopping operating time of the rig equipment such that operation of the rig equipment that generates the rig noise that interferes with the telemetry signal does not happen at the same time as operation of the telemetry system.

Changing the operational parameters of the telemetry system may comprise changing the operational parameters of the telemetry system such that an operating frequency range of the telemetry system does not overlap with a frequency range of the rig noise signature.

Changing the operational parameters of the telemetry system may comprise changing starting and/or stopping operating time of the telemetry system such that operation of the telemetry system does not happen at the same time as operation of the rig equipment that generates the rig noise that interferes with the telemetry signal.

The equipment controller may be further operable to store associations between each instance of the rig equipment and a corresponding instance of the rig noise signature caused by each instance of the rig equipment, and the equipment controller may be operable to output control commands to an instance of the rig equipment to reduce a corresponding instance of the rig noise and thereby reduce interference of the rig noise with the telemetry signal based on the stored associations. The equipment controller may be further operable to store a digital well construction plan for operating the telemetry system and the rig equipment to construct a well, and the equipment controller may be further operable to change the digital well constriction plan and thereby reduce interference of the rig noise with the telemetry signal based on the stored associations.

The equipment controller may be further operable to store a digital plan for operating the telemetry system and the rig equipment to construct a well, and the equipment controller may be further operable to change the digital plan to reduce interference of the rig noise with the telemetry signal. Changing the digital plan to reduce interference of the rig noise with the telemetry signal may comprise changing starting and/or stopping operating time of the rig equipment such that operation of the rig equipment that generates the rig noise that interferes with the telemetry signal does not happen at the same time as operation of the telemetry system.

The present disclosure also introduces a method comprising: commencing operation of a telemetry system of a drilling rig; and commencing operation of an equipment controller of the drilling rig, thereby causing the equipment controller to output control commands to change operational parameters of the telemetry system and/or rig equipment of the drilling rig to reduce interference by rig noise with a telemetry signal.

Commencing operation of the telemetry system of the drilling rig may cause: (A) the telemetry signal to be transmitted by a transmitter carried by a drill string; and (B) an output signal to be generated by a receiver included in surface equipment of the drilling rig, wherein the output signal comprises: (i) a telemetry signal signature based on the telemetry signal; and (ii) a rig noise signature based on the rig noise generated by the rig equipment of the drilling rig. The equipment controller may be operable to store associations between each instance of the rig equipment and a corresponding instance of the rig noise signature caused by each instance of the rig equipment, and commencing operation of the equipment controller may cause the equipment controller to output control commands to an instance of the rig equipment to reduce a corresponding instance of the rig noise and thereby reduce interference by the rig noise with the telemetry signal based on the stored associations.

The equipment controller may be operable to store a digital plan for operating the telemetry system and the rig equipment to construct a well, and commencing operation of the equipment controller may cause the equipment controller to change the digital plan to reduce interference of the rig noise with the telemetry signal.

The present disclosure also introduces a method comprising: commencing operation of a telemetry system a drilling rig; and manually operating a control workstation of the drilling rig by a rig personnel to change operational parameters of the rig equipment and/or the telemetry system to reduce interference by rig noise with a telemetry signal.

Commencing operation of the telemetry system of the drilling rig may cause: (A) the telemetry signal to be transmitted by a transmitter carried by a drill string; and (B) an output signal to be generated by a receiver included in surface equipment of the drilling rig, wherein the output signal comprises: (i) a telemetry signal signature based on the telemetry signal; and (ii) a rig noise signature based on rig noise generated by rig equipment of the drilling rig. The method may further comprise commencing operation of a processing device of the drilling rig, thereby causing the telemetry signal signature and the rig noise signature to be displayed by the processing system on a video output device for viewing by rig personnel. Manually operating the control workstation of the drilling rig by the rig personnel to reduce interference by the rig noise with the telemetry signal may be based on the displayed telemetry signal signature and the rig noise signature. The processing device may be operable to store associations between each instance of the rig equipment and a corresponding instance of the rig noise signature, and commencing operation of the processing device may further cause the associations between each instance of the rig equipment and the corresponding instance of the rig noise signature to be displayed on the video output device for viewing by the rig personnel.

The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the scope of the present disclosure.

The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. 

What is claimed is:
 1. An apparatus comprising: a telemetry system of a drilling rig, wherein the telemetry system comprises: a transmitter carried by a drill string and operable to transmit a telemetry signal; and a receiver included in surface equipment of the drilling rig and operable to generate an output signal comprising: a telemetry signal signature based on the telemetry signal; and a rig noise signature based on rig noise generated by rig equipment of the drilling rig; and an equipment controller comprising a processor and a memory storing computer program code, wherein the equipment controller is operable to automatically reduce interference by the rig noise with the telemetry signal by outputting control commands to change operational parameters of the rig equipment and/or the telemetry system.
 2. The apparatus of claim 1 wherein the telemetry signal comprises at least one of a mud-pulse telemetry signal and electromagnetic telemetry signal.
 3. The apparatus of claim 1 wherein the telemetry signal signature is indicative of frequency of the telemetry signal and the rig noise signature is indicative of frequency of the rig noise.
 4. The apparatus of claim 1 wherein: the receiver is or comprises a pressure sensor; the telemetry signal comprises pressure fluctuations propagating through drilling fluid flowing within the drill string and the surface equipment; the receiver is further operable to receive the telemetry signal and the rig noise; and the output signal is an electrical signal comprising the telemetry signal signature and the rig noise signature.
 5. The apparatus of claim 1 wherein: the receiver is or comprises an electromagnetic signal sensor; the telemetry signal comprises an electromagnetic signal transmitted through rock formation extending between the transmitter and the receiver; the receiver is further operable to receive the telemetry signal and the rig noise; and the output signal is an electrical signal comprising the telemetry signal signature and the rig noise signature.
 6. The apparatus of claim 1 wherein changing the operational parameters of the rig equipment comprises changing the operational parameters of the rig equipment such that a frequency range of the rig noise signature does not overlap with a frequency range of the telemetry signal signature.
 7. The apparatus of claim 1 wherein changing the operational parameters of the rig equipment comprises changing starting and/or stopping operating time of the rig equipment such that operation of the rig equipment that generates the rig noise that interferes with the telemetry signal does not happen at the same time as operation of the telemetry system.
 8. The apparatus of claim 1 wherein changing the operational parameters of the telemetry system comprises changing the operational parameters of the telemetry system such that an operating frequency range of the telemetry system does not overlap with a frequency range of the rig noise signature.
 9. The apparatus of claim 1 wherein changing the operational parameters of the telemetry system comprises changing starting and/or stopping operating time of the telemetry system such that operation of the telemetry system does not happen at the same time as operation of the rig equipment that generates the rig noise that interferes with the telemetry signal.
 10. The apparatus of claim 1 wherein the equipment controller is further operable to store associations between each instance of the rig equipment and a corresponding instance of the rig noise signature caused by each instance of the rig equipment, and wherein the equipment controller is operable to output control commands to an instance of the rig equipment to reduce a corresponding instance of the rig noise and thereby reduce interference of the rig noise with the telemetry signal based on the stored associations.
 11. The apparatus of claim 10 wherein the equipment controller is further operable to store a digital well construction plan for operating the telemetry system and the rig equipment to construct a well, and wherein the equipment controller is further operable to change the digital well constriction plan and thereby reduce interference of the rig noise with the telemetry signal based on the stored associations.
 12. The apparatus of claim 1 wherein the equipment controller is further operable to store a digital plan for operating the telemetry system and the rig equipment to construct a well, and wherein the equipment controller is further operable to change the digital plan to reduce interference of the rig noise with the telemetry signal.
 13. The apparatus of claim 12 wherein changing the digital plan to reduce interference of the rig noise with the telemetry signal comprises changing starting and/or stopping operating time of the rig equipment such that operation of the rig equipment that generates the rig noise that interferes with the telemetry signal does not happen at the same time as operation of the telemetry system.
 14. A method comprising: commencing operation of a telemetry system of a drilling rig; and commencing operation of an equipment controller of the drilling rig, thereby causing the equipment controller to output control commands to change operational parameters of the telemetry system and/or rig equipment of the drilling rig to reduce interference by rig noise with a telemetry signal.
 15. The method of claim 14 wherein commencing operation of the telemetry system of the drilling rig causes: the telemetry signal to be transmitted by a transmitter carried by a drill string; and an output signal to be generated by a receiver included in surface equipment of the drilling rig, wherein the output signal comprises: a telemetry signal signature based on the telemetry signal; and a rig noise signature based on the rig noise generated by the rig equipment of the drilling rig.
 16. The method of claim 15 wherein the equipment controller is operable to store associations between each instance of the rig equipment and a corresponding instance of the rig noise signature caused by each instance of the rig equipment, and wherein commencing operation of the equipment controller causes the equipment controller to output control commands to an instance of the rig equipment to reduce a corresponding instance of the rig noise and thereby reduce interference by the rig noise with the telemetry signal based on the stored associations.
 17. The method of claim 14 wherein the equipment controller is operable to store a digital plan for operating the telemetry system and the rig equipment to construct a well, and wherein commencing operation of the equipment controller causes the equipment controller to change the digital plan to reduce interference of the rig noise with the telemetry signal.
 18. A method comprising: commencing operation of a telemetry system a drilling rig; and manually operating a control workstation of the drilling rig by a rig personnel to change operational parameters of the rig equipment and/or the telemetry system to reduce interference by rig noise with a telemetry signal.
 19. The method of claim 18 wherein: commencing operation of the telemetry system of the drilling rig causes: the telemetry signal to be transmitted by a transmitter carried by a drill string; and an output signal to be generated by a receiver included in surface equipment of the drilling rig, wherein the output signal comprises: a telemetry signal signature based on the telemetry signal; and a rig noise signature based on rig noise generated by rig equipment of the drilling rig; and the method further comprises commencing operation of a processing device of the drilling rig, thereby causing the telemetry signal signature and the rig noise signature to be displayed by the processing system on a video output device for viewing by rig personnel; and manually operating the control workstation of the drilling rig by the rig personnel to reduce interference by the rig noise with the telemetry signal is based on the displayed telemetry signal signature and the rig noise signature.
 20. The method of claim 19 wherein the processing device is operable to store associations between each instance of the rig equipment and a corresponding instance of the rig noise signature, and wherein commencing operation of the processing device further causes the associations between each instance of the rig equipment and the corresponding instance of the rig noise signature to be displayed on the video output device for viewing by the rig personnel. 